As Nigerian operations expand into more challenging and costly operating environments of deepfrontiers, there is need for critical access to sound stratigraphic, depositional and reservoir facies models. The extraction of facies types from geometric insights and pattern recognition using predominantly 3D seismic data is a rapidly evolving discipline that facilitates the development of reservoir prediction models linked to significant plays. Play based exploration approach such as this provides the critical link between regional observations and prospect generation. In this study a regional dataset which comprised of a merged 3D seismic volume, well logs, biostratigraphic, biofacies, paleobathymetry and core data from Eastern Niger Delta was interpreted. Results clearly show the overall structural, stratigraphic and architectural styles within the region to ensure that successes achieved in the past can be repeated and also significant advances made to ensure future exploration success. An added outcome is a low-risk exploration workflow that is capable of correctly predicting reservoir rocks to be encountered in a new play and prospect. Three plays have been identified from this study: (1) shelf edge deltas, (2) pinch-out play and (3) hanging wall play. Each play displays a unique morphology, seismic expression, structural configuration, migration pathway, seal integrity and reservoir dispersal pattern. These prediction models provide play based exploration targets for areas with similar depositional settings. The successful application of this technique serve to encourage exploration in the Niger Delta Basin by adopting strategies where seismic stratigraphy will be the most likely means to provide drilling targets to more independent operators.
An integrated structural and stratigraphic analysis of a regional dataset from Eastern Niger Delta was undertaken with the objective of improving the present understanding of the structural development, seismic reflection geometries and implication on sand transportation and deposition within the shelf-edge and farther into the basin floor. Well log correlations were carried out using third-order sequence stratigraphy. Fault dynamics and evolution was interpreted with the aid of seismic transect sections, growth fault indexes and dip-extracted semblance slices. Lithofacies and paleobathymetric data were utilized to create gross depositional environment maps for the various sequences from inner-shelf to upper slope environment. The fault dynamics and evolution analysis of co-planar faults shows that older co-planar faults are associated with more accommodation space and depocentres than relatively younger faults. Conceptual subsurface models from this study shows that there is an increase in sand thickness in the proximal part of the sequence associated with precursor (older) faults, while towards the distal part, it reduces. There is also a relative decrease in sand thickness in the proximal part of the sequence associated with younger initiated faults, while towards the distal part, it increases in sand thickness. This study shows that at the shelf-edge, the thickest sand is of the lowstand system tract and the possibility of transporting sands into the basin is more associated with younger co-planar faults with small accommodation space at the shelf-edge, while the precursor older faults retain majority of sand deposits within its subsidence/depocentre axis.
This study was carried out integrating well logs and core to build reservoir model for the Useni-1 oil field. Core data and well logs were used to evaluate the petrophysical characteristics of the reservoirs. The paleodepositional environment was deduce from the wells and cores data. The depositional facies model showed highly permeable channels where the wells where positioned. The environments identified that the fluvial channel facies with highly permeable zones constituted the reservoirs. Four reservoirs were mapped at depth range of 8000ft to 8400ft with thicknesses varying from 20ft to 400ft. Petrophysical results showed that porosity of the reservoirs varied from 12% to 28 %; permeability from 145.70 md to 454.70md; water saturation from 21.65% to 54.50% and hydrocarbon saturation from 45.50% to 78.50 %. Core data and the gamma ray log trends with right boxcar trend indicate fluvial point bar and tidal channel fills in the lower delta plain setting. By-passed hydrocarbons were identified in low resistivity pay sands D1, D2 at depth of 7800 – 78100ft in the field.
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